The invention relates to the treatment of natural gas that is out of specification with respect to nitrogen and carbon dioxide. More particularly, the invention relates to the removal of nitrogen and carbon dioxide from such natural gas by means of gas-separation membranes.
Fourteen percent of known U.S. natural gas reserves contain more than 4% nitrogen. The gas in as many as a third or more of these reserves also contains more than 2% carbon dioxide, making it sub-quality with regard to both gases. Significant amounts of gas are also contaminated by hydrogen sulfide, for which pipeline specification is lower than 4 ppm. Such reserves cannot be exploited because no economical technology for removing the nitrogen exists.
Cryogenic distillation is the only process that has been used to date on any scale to remove nitrogen from natural gas. The gas streams that have been treated by cryogenic distillation, for example streams from enhanced oil recovery, have large flow rates and high nitrogen concentration, such as more than 10 vol %. Cryogenic plants can be cost-effective in these applications because all the separated products have value. The propane, butane and heavier hydrocarbons can be recovered as natural gas liquids (NGL), the methane/ethane stream can be delivered to the gas pipeline and the nitrogen can be reinjected into the formation.
Cryogenic plants are not used more widely because they are costly and complicated. A particular complication is the need for significant pretreatment to remove water vapor, carbon dioxide and C3+ hydrocarbons and aromatics to avoid freezing of these components in the cryogenic section of the plant, which typically operates at temperatures down to xe2x88x92150xc2x0 C. The degree of pretreatment is often far more elaborate and the demands placed upon it are far more stringent than would be required to render the gas acceptable in the pipeline absent the excess nitrogen content.
For example, pipeline specification for water vapor is generally below about 120 or 140 ppm; to be fit to enter a cryogenic plant, the gas must contain no more than 1-2 ppm of water vapor at most. Similarly, 2% carbon dioxide content may pass muster in the pipeline, whereas carbon dioxide must be present at levels no higher than about 100 ppm for cryogenic separation. For streams of flow rates less than about 50-100 MMscfd, therefore, cryogenic technology is simply too expensive and impractical for use.
Other processes that have been considered for performing this separation include pressure swing adsorption and lean oil absorption; none is believed to be in regular industrial use.
The potential production of gas containing 10 to 30% nitrogen is about 8,500 MMscfd. At present, approximately 4,500 MMscfd of this gas is treated by cryogenic processes, leaving about 4,000 MMscfd of gas unused because it is unsuitable for cryogenic treatment. Much of this gas is in small fields and is contaminated with carbon dioxide or/and hydrogen sulfide.
Gas separation by means of membranes is known. For example, numerous patents describe membranes and membrane processes for separating oxygen or nitrogen from air, hydrogen from various gas streams and carbon dioxide from natural gas. Such processes are in industrial use, using glassy polymeric membranes. Rubbery polymeric membranes are used to separate organic components from air or other gas mixtures.
A report by SRI to the U.S. Department of Energy (xe2x80x9cEnergy Minimization of Separation Processes using Conventional Membrane/Hybrid Systemsxe2x80x9d, D. E. Gottschlich et al., final report under contract number DE 91-004710, 1990) suggests that separation of nitrogen from methane might be achieved by a hybrid membrane/pressure swing adsorption system. The report shows and considers several designs, assuming that a hypothetical nitrogen-selective membrane, with a selectivity for nitrogen over methane of between 5 and 15 and a transmembrane methane flux of 1xc3x9710xe2x88x926 cm3(STP)/cm2xc2x7sxc2x7cmHg, were to become available, which to date it has not.
In fact, both glassy and rubbery polymers have poor selectivities for nitrogen over methane or methane over nitrogen. Table 1 lists some representative values for glassy materials.
The problem of separating gas mixtures containing methane and nitrogen into a methane-rich stream and a nitrogen-rich stream is, therefore, a very difficult one, owing to the low selectivity of essentially all membrane materials to these gases. In addition, many materials that are somewhat selective for one gas over the other have very low permeability.
U.S. Pat. No. 3,616,607 to Northern Natural Gas Company, discloses membrane-based separation of nitrogen from methane for natural gas treatment. The patent reports extraordinarily high nitrogen/methane selectivities up to 15 and 16. These numbers are believed to be erroneous and have not been confirmed elsewhere in the literature. Also, the membranes with these alleged selectivities were made from polyacrylonitrile, a material with extremely low gas permeability of the order 10xe2x88x924 Barrer (ten thousandths of a Barrer) that would be impossible to use for a real process.
It was discovered a few years ago that operating silicone rubber membranes at low temperatures can increase the methane/nitrogen selectivity to as high as 5 or above. U.S. Pat. Nos. 5,669,958 and 5,647,227 make use of this discovery and disclose low-temperature methane/nitrogen separation processes using silicone rubber or similar membranes to preferentially permeate methane and reject nitrogen. However, such a selectivity is obtained only at very low temperatures, typically xe2x88x9260xc2x0 C., for example. Temperatures this low generally cannot be reached by relying on the Joule-Thomson effect to cool the membrane permeate and residue streams, but necessitate additional chilling by means of external refrigeration. While such processes may be workable in industrial facilities with ready access to refrigeration plants, they are impractical in many gas fields, where equipment must be simple, robust and able to function for long periods without operator attention.
Another problem of operating membranes at very low temperature operation is that, just as in conventional cryogenic plants, significant pretreatment is required to avoid system blockages and damage caused by methane hydrate formation or freezing of higher boiling point stream components individually.
A significant problem when rubbery, methane-selective membranes are used is co-permeation of carbon dioxide, hydrogen sulfide, and water that may also be present in the gas. These components permeate the first set of membrane modules and are concentrated in the natural gas product that is to be sent to the pipeline. Since more than one third of the unexploited high-nitrogen gas reserves are also out of specification for carbon dioxide or hydrogen sulfide, this is potentially a common problem. Gas treated in this way also needs dehydration and acid gas removal before delivery to the pipeline. The additional cost and complexity of these additional steps can make the process uneconomical.
Further concerns that hamper membrane process design for methane/nitrogen separation are that vacuum pumps generally must not be used anywhere in the system as they may permit air to leak into lines carrying hydrocarbon mixtures, representing an unacceptable safety hazard. Indeed, for safety, reliability and cost-containment, the number of pieces of rotating or moving equipment of any kind should be kept to a minimum.
In view of these multiple difficulties, there remains an unsatisfied need for economical means of exploiting nitrogen-rich natural gas reserves, especially those contained in gas fields with smaller flow rates.
The invention is a process for treating natural gas or other methane-rich gas to remove excess nitrogen and carbon dioxide simultaneously. The gas to be treated usually contains at least about 4% nitrogen and at least about 2% carbon dioxide.
In another aspect, the invention is a process that can remove multiple components from a gas stream contaminated with nitrogen, acid gases or water vapor, and can thereby produce pipeline-quality gas in a single membrane process.
The invention relies on membrane separation using a two-step membrane system design. The membranes used in both steps are permeable to carbon dioxide, water, hydrogen sulfide, and nitrogen but relatively impermeable to methane.
In a basic aspect, the process of the invention includes the following steps for treating a feed gas stream:
(a) providing a first membrane unit containing a first membrane having a first feed side and a first permeate side, the first membrane being more permeable to all of nitrogen, carbon dioxide, hydrogen sulfide and water vapor than to methane;
(b) providing a second membrane unit containing a second membrane having a second feed side and a second permeate side, the second membrane being more permeable to all of nitrogen, carbon dioxide, hydrogen sulfide and water vapor than to methane, the second membrane unit being connected in series with the first membrane unit such that gas leaving the first feed side can enter the second membrane unit on the second feed side;
(c) passing a gas stream at a first pressure into the first membrane unit and across the first feed side;
(d) withdrawing from the first feed side a first residue stream enriched in methane and depleted in nitrogen and carbon dioxide compared with the gas stream;
(e) withdrawing from the first permeate side, at a second pressure lower than the first pressure, a first permeate stream depleted in methane and enriched in nitrogen and enriched in carbon dioxide compared with the gas stream;
(f) passing the first residue stream into the second membrane unit and across the second feed side;
(g) withdrawing from the second feed side as a product stream a second residue stream enriched in methane compared with the first residue stream, and containing no more than about 6% nitrogen and no more than about 3% carbon dioxide;
(h) withdrawing from the second permeate side, at a third pressure lower than the first pressure, a second permeate stream depleted in methane and enriched in nitrogen and enriched in carbon dioxide compared with the first residue stream.
The first membrane unit produces a permeate gas containing most of the carbon dioxide present in the original feed, as well as almost all the hydrogen sulfide and water vapor, if present, and some of the nitrogen.
The first permeate stream can be flared or used as fuel, for example. As a preferred alternative, it is possible to include a third membrane unit to treat the first permeate stream by fractionating it into a comparatively methane-rich residue stream, which may be recirculated within the process for additional methane recovery, and a comparatively nitrogen-rich and carbon-dioxide-rich third permeate stream, which may be flared, used as fuel, reinjected, or sent to any other destination as desired.
The high-pressure residue gas from the first membrane unit, now reduced in contaminants, is sent to the second membrane unit, which removes the remaining excess nitrogen and other contaminants. The residue gas from the second membrane step typically contains methane and ethane, as well as other hydrocarbons, if present in the original feed gas. This gas has been reduced to the chosen target specification for nitrogen, and is substantially free of carbon dioxide, hydrogen sulfide and water vapor. The gas is at high pressure and may be delivered to the pipeline, if appropriate, without further treatment.
The permeate from the second membrane separation step frequently contains too much methane for the stream to be discharged to waste. Preferred embodiments of the invention include recirculating this permeate stream from the second membrane separation step to the front of the process to increase methane recovery.
By adopting one of these preferred embodiments, the fuel to run any compressor needed for the process can often be generated as a discrete product stream by the process itself. This is very beneficial as gas-fired compressors can operate in remote locations where an electrical power supply is unavailable.
The process of the invention offers a number of additional features and advantages. Importantly, it enables natural gas containing relatively large amounts of nitrogen, such as 10%, 20% or higher, to be brought close to or within pipeline specification of no more than 4% nitrogen. Even more importantly, natural gas that is out of specification not just with respect to nitrogen, but also with respect to carbon dioxide, can be brought within specification for both of these components simultaneously by a single treatment.
Likewise gas that contains either excess hydrogen sulfide or water vapor, or both, in addition to being out of specification with respect to nitrogen and carbon dioxide, can be brought within specification for all components simultaneously.
This ability to meet the xe2x80x9ctotal inertsxe2x80x9d, hydrogen sulfide and water requirements of pipeline gas in one operation avoids a multitude of potential problems and additional processing requirements downstream of the membrane separation operations.
Furthermore, for small gas streams or remote gas fields, these beneficial results can be achieved more simply, reliably and cheaply than could be done with prior art technology.
In comparison, conventional technology to treat such streams would be to use an amine absorption plant to remove the carbon dioxide and hydrogen sulfide, followed by a glycol absorption unit to remove water and a cryogenic plant to remove the nitrogen. The complexity and combined cost of these multiple operations is excessive, and for operators of smaller fields and wells, such as those with gas flows lower than about 50 MMscfd or lower than about 100 MMscfd, can be completely prohibitive.
Even if the other benefits of membrane separation were achieved by using methane-selective membranes, as described in U.S. Pat. Nos. 5,669,958 and 5,647,227 or copending application Ser. No. 09/917,478, now U.S. Pat No. 6,425,267, pretreatment or post-treatment of gas to remove acid gases and water vapor would often be necessary.
Thus the process of the invention provides an opportunity to open up for production a very large amount, in the billions of scfd, of currently shut-in gas.
Another important advantage of the process of the invention, in many embodiments, is that only one compressor is needed to operate the entirety of the process, that is, to produce dry, low-nitrogen, low-carbon dioxide pipeline-quality gas at high pressure. The membrane separation units are completely passive pieces of equipment, with no moving parts, no consumable supplies, such as sorbents or catalysts, and no operating fluids that require periodic changing or regeneration.
Thus the simplicity and reliability of the process is in sharp contrast to conventional processes that typically require multiple pumps to adjust gas conditions for different unit operations and to move gas from one unit operation to the next, as well as needing skilled operators and regular maintenance.
Also, unlike prior art membrane processes disclosed in the literature, specifically the SRI report mentioned above and U.S. Pat. Nos. 5,669,958 and 5,647,227, a membrane selectivity between methane and nitrogen of at least 5 is not required. The two-step membrane process configuration provides adequate performance, in terms of the total inerts content and the water dewpoint, even when the membrane selectivity is as low as around 2, for example. If higher selectivity than can be achieved at room temperature is desired, therefore, it can be provided in most cases simply by taking advantage of the cooling by Joule-Thomson effect of both permeate and residue streams that takes place in membrane separation processes.
This effect is discussed at length in, for example, U.S. Pat. No. 5,762,685. The feed and permeate sides of a membrane are separated only by the very thin polymer membrane layer and are in good thermal contact. Thus, although it is expansion to the permeate side that produces the cooling, membrane separation of a gas stream containing organic components typically results in the residue stream, as well as the permeate, being significantly colder than the gas that was fed to the membrane. In experimental tests, we have found in some cases that the residue and permeate streams are at about the same temperature; in other cases that the residue stream is the colder. Either the residue or the permeate, or both, can, therefore, be used to cool the incoming gas.
Such cooling can be accomplished by heat exchange between the membrane feed, residue and permeate streams, and optionally by expanding the membrane residue stream before such heat exchange, without the need for any external refrigeration source. In general, the process can be operated at temperatures above about xe2x88x9225xc2x0 C., above about xe2x88x9210xc2x0 C. or even around 0xc2x0 C., 10xc2x0 C. or above. The ability to function at these comparatively high temperatures and without external cooling in many instances is a particular advantage of the present invention, as it greatly simplifies the process compared with prior art technologies.
In fact, usually the average temperatures of the membrane separation units and incoming and outgoing streams can be kept above about xe2x88x9225xc2x0 C. In this case, metal components of the equipment can be made from carbon steel rather than stainless steel, with considerable cost savings.
The most important product of the process is the methane-rich second residue stream. This product gas is provided from the high-pressure side of the membrane separation system. This is a particular advantage when compared with the prior art processes using methane-selective membranes, where the product natural gas is withdrawn at comparatively low pressure, and results in a beneficial savings in recompression costs.
The process in its most basic embodiment as described above results in a methane product stream of good quality, typically able to meet pipeline specification, and two methane-depleted, contaminant-enriched permeate streams. As mentioned above, the permeate from the second membrane separation step can advantageously be recirculated to the front of the process to increase methane recovery. In this case, it is preferred if the operating parameters of the process are adjusted as described in more detail below to achieve a nitrogen content in the second permeate stream that is similar to the nitrogen content in the feed gas stream. This avoids the inefficiencies associated with mixing streams of unlike compositions.
The permeate from the first membrane separation step is the most nitrogen-rich stream produced by the basic process of the invention. If the feed gas has a very high nitrogen content, such as more than 20% nitrogen, this permeate stream may contain as much as about 40% nitrogen or more. In this case, this stream has value as a potential source of nitrogen, such as for reinjection into the formation producing the raw gas.
More usually, the first permeate stream contains about 20% or 30% nitrogen, and still contains about 50% methane or more. Gas of this composition generally has a Btu value of at least about 500 Btu/scf, high enough to be a good source of compressor fuel gas.
As mentioned above, a particularly preferred embodiment of the invention uses a third membrane separation unit as a second membrane separation stage to further treat this permeate stream. In that case, the process of the invention includes the following steps:
(a) providing a first membrane unit containing a first membrane having a first feed side and a first permeate side, the first membrane being more permeable to all of nitrogen, carbon dioxide, hydrogen sulfide and water vapor than to methane;
(b) providing a second membrane unit containing a second membrane having a second feed side and a second permeate side, the second membrane being more permeable to all of nitrogen, carbon dioxide, hydrogen sulfide and water vapor than to methane, the second membrane unit being connected in series with the first membrane unit such that gas leaving the first feed side can enter the second membrane unit on the second feed side;
(c) providing a third membrane unit containing a third membrane having a third feed side and a third permeate side, the third membrane being more permeable to all of nitrogen, carbon dioxide, hydrogen sulfide and water vapor than to methane, the third membrane unit being connected in series with the first membrane unit such that gas leaving the first permeate side can enter the third membrane unit on the third feed side;
(d) passing a gas stream at a first pressure into the first membrane unit and across the first feed side;
(e) withdrawing from the first feed side a first residue stream enriched in methane and depleted in nitrogen and carbon dioxide compared with the gas stream;
(f) withdrawing from the first permeate side, at a second pressure lower than the first pressure, a first permeate stream depleted in methane and enriched in nitrogen and enriched in carbon dioxide compared with the gas stream;
(g) passing the first residue stream into the second membrane unit and across the second feed side;
(h) withdrawing from the second feed side as a product stream a second residue stream enriched in methane compared with the first residue stream, and containing no more than about 6% nitrogen and no more than about 3% carbon dioxide;
(i) withdrawing from the second permeate side, at a third pressure lower than the first pressure, a second permeate stream depleted in methane and enriched in nitrogen and enriched in carbon dioxide compared with the first residue stream;
(j) passing the first permeate stream into the third membrane unit and across the third feed side;
(k) withdrawing from the third feed side a third residue stream enriched in methane compared with the first permeate stream;
(l) withdrawing from the third permeate side, at a fourth pressure lower than the first pressure, a third permeate stream depleted in methane and enriched in nitrogen and enriched in carbon dioxide compared with the first permeate stream.
The processes of the invention are principally directed to treating various types of natural gas streams, such as those arising from gas wells, oil wells or landfills. However, the processes are applicable, and are expected to be of value, in treating any gas streams that contain a mix of methane and nitrogen with acid gas and/or water vapor. Representative, non-limiting examples of such streams are streams produced during coal gasification, syngas manufacture and related gas-to-liquids technologies.
It is an object of the invention to provide a process for removing excess nitrogen and carbon dioxide from methane-containing gas mixtures.
It is an object of the invention to provide a process for bringing raw natural gas into specification for nitrogen and carbon dioxide in a simple manner.
It is an object of the invention to provide a simple, reliable and cost-effective method for processing nitrogen- and carbon-dioxide-contaminated natural gas from small or remote fields.
It is an object of the invention to provide a membrane-based process for processing nitrogen- and carbon-dioxide-contaminated natural gas that also generates combustion fuel to drive the process.
Other objects and advantages will be apparent from the description of the invention to those skilled in the gas separation arts.